12 Oil and Gas Companies to follow in 2022
The oil and gas sector has had an opportunity to take advantage of much more favourable conditions this year than those that prevailed through 2020.
Energy prices have soared as the global economy has made a stuttering recovery, driving demand that has exposed significant supply constraints. The surge in the value of natural gas has been particularly spectacular, European prices reaching a record high of €117.50/MWh in October, with the outlook remaining strong going into the new year. European gas futures surged 11pc earlier this month as traders feared the refusal of the new German government to give the green light for the Nord Stream 2 pipeline and Russian military build-up on the Ukrainian border will reduce storage levels to critically low levels by the spring. Asian demand continues to soar, driven by coal-to-gas switching and the need to support intermittent renewables generation, with inadequate domestic production leaving China and other fast growing economies dependent on imported LNG. Rising US energy prices have prompted the President to authorise the largest-ever release of oil from America’s emergency stockpile and urge Saudi Arabia to keep increasing monthly crude oil production.
That the environmentally sensitive Biden administration should have been prepared to make such an appeal is another sign that fossil fuel energy will be with us for some decades to come. An International Energy Agency report notes that although a record amount of renewable electricity was added to global energy systems this year it remains about half of what is needed annually to be on track to reach net zero emissions by 2050.
But though 2021 has offered a measure of breathing space after last year’s trials the industry continues to face stark political and economic challenges. Pressure exerted by increasingly stringent climate change regulations and growing investor reluctance to fund fossil fuel exploration is casting an every deeper shadow over the sector’s licence to operate. Shell’s decision to back out of the Cambo project indicates the existential threat that now faces operators pursuing new developments in UK waters. Though the industry may be right to note that failure to invest in new fields will accentuate the UK’s reliance on imports, the political tide is changing, fast. Non-listed operators, which have enjoyed considerable backing by private equity, should also expect increasing scrutiny.
The industry will also have to cope with the issues facing the wider economy, such as rising inflation and Covid’s untimely resurgence: oil prices stuttered again this month as Omicron spread, and some analysts forecast that the oil market will again tip into surplus early next year. But though warning of all these dangers, energy consultant Wood Mackenzie’s 2022 Global Upstream Outlook sounds positive notes, expecting that continued high prices will support cash flows able to fund exploration spend of around $20 to $25bn, generating discoveries of around 15 to 20bn boe worth.
Opportunities exist, then, for small cap energy investors who choose wisely. We’ve picked out companies that have solid production prospects, intriguing exploration targets, and sufficient cash to fund their current operations. Some are dark horses that may have strengths that may have been overlooked by the market. We were interested to note how many of these small companies are now paying real attention to their carbon footprint, a consideration no longer limited to the majors. Thank you to regular TMS readers for following our coverage of the energy small cap sector through 2021: we hope this year’s roundup offers some interesting insights as the year ends.
Companies covered include:
#BLOE #CHAR #ECHO #EDR #IGAS #JOG #LBE #NTOG #PXEN #UJO #WTE #ZPHR
Block Energy (AIM:BLOE) continues to seek lift-off in its attempt to unlock the potential of a set of oil and gas assets in the the former Soviet country of Georgia through the use of contemporary drilling technology.
The company listed in the summer of 2018 with a cluster of fields a few miles south east of Georgia’s capital city Tbilisi, notably West Rustavi, which produced 50 Mbbls of light sweet crude under the USSR, and which has contingent resources of 38 MMbbls oil and 608 BCF gas in the Middle, Upper and Lower Eocene formations. Block achieved only modest results from initial drilling at the first few wells it reopened at West Rustavi through 2019 and early last year, but recorded unexpectedly high gas-to-oil ratios, prompting the company to accelerate its gas offtake strategy. An agreement was struck with a local gas supply company for the offtake of West Rustavi gas with a view to serving a growing Georgian energy market almost completely dependent on imports from neighbouring countries.
Last year Block acquired substantial new assets adjacent to West Rustavi that had previously been operated by Schlumberger through a cash-free deal granting the oil giant 23.3pc of the smaller company’s shares. The potentially transformative acquisition multiplied Block’s acreage more than 30 times, and opened several new development opportunities including Block XIB, which prior to Schlumberger’s ownership had produced more than 180 million bbls of oil from the Middle Eocene, rates peaking in the 1980s at 67,000 bopd. Block’s new assets increased the company’s 2P reserves of oil and gas by 64 MMboe, 2C contingent resources by 29 million boe, and prospective resources by 245 MMboe.
Block undertook a fundraise last December to raise £5.28m to fund its current drilling programme focused on West Rustavi’s WR-B1a and JKT-01 wells. This October the company reported that well productivity was being restricted owing to the natural fractures being clogged with loss circulation material, which had been used to prevent the large drilling fluid losses experienced when opening up the company’s previous West Rustavi wells. Drilling at the JKT-01Z sidetrack, targeting a polygon that potentially contains 2.4 MMboe of recoverable oil and gas reserves, is now underway. Following the interim installation of a rod pump WR-B1a is producing an average of 50bopd. That rate was significantly below expectations, but a low-cost sidetrack is planned to ‘target significant fractures and faults’, and operations thus far have facilitated ‘greater understanding of the reservoir’ that have ‘informed the placement of the JKT-01 wellbore’.
Block has a lot riding on success at JKT-01Z, but as at 30 September 2021 it still had $2.7m cash to support current operations, and it is generating revenue from oil and gas sales across its licences, which have benefiting from the energy price surge. During Q3 the company sold 11.2 Mbbls of oil for $742,000, and 52.4 MMcf of gas for $159,000. The company brought its gas Early Production Facility at West Rustavi online in February. Its average gross oil production in Q3 was 376 boepd.
Block Energy has tantalised and frustrated investors, its share price hitting highs of around 18p when West Rustavi showed early promise in 2019, before zig-zagging all the way down to 1p at the time of writing. The company needs a result in its current campaign to avoid returning to the market for cash, but has now accumulated considerable data to de-risk its interventions.
Chariot (AIM:CHAR), however, is an interesting example of the trend for small caps to seek to evolve into transitional energy companies, following the path beaten by many of the majors. The company is organised into two business streams, Chariot Transitional Gas, focused on a gas development project offshore Morocco, and Chariot Transitional Power, working to develop a portfolio of low carbon mining operations throughout Africa.
Lixus, the company’s Morocco licence, contains the Anchois gas discovery, which has an audited total remaining recoverable resource of more than 1Tcf, comprising 361Bcf 2C contingent resources and 690Bcf 2U prospective resources. Appraisal drilling aiming to identify and develop a future production well got underway earlier this month, with operations to drill the Anchois-2 gas appraisal and exploration well and re-enter the previously drilled Anchois-1 gas discovery expected to take up to 40 days.
Chariot has being building its Transitional Power stream through the acquisition of Africa Energy Management Platform, which explores solutions for reducing the carbon footprint of the continent’s mining industry in Africa, and an agreement with power producer Total Eren giving Chariot the right to invest up to 15pc project in Eren’s 500MW pipeline of African mining power projects. Chariot already has a 10pc share in the partners’ first project in operation, the hybrid solar plant at the Essakane gold mine in Burkina Faso, which generates solar energy through 130,000 photovoltaic panels.
Chariot has also signed an MoU with the Government of Mauritania to progress a potential green hydrogen development. Pre-feasibility and feasibility studies will examine a 14,400km2 onshore and offshore area with the intention of generating electricity from solar and wind resources that will then be used in electrolysis to split water to produce green hydrogen and oxygen.
Earlier this month the company secured funds for its current activities with a placing worth a gross $11m. Its most recent interims reported a cash balance as at 30 June 2021 of $18m.
With a share price currently at 7.3p, down from a high of 10.5p in March, but on an upward curve again, Chariot is pursuing in a range of initiatives that may be of particular interest to investors looking for opportunities to take a stake in the developing world’s energy transition.
South American-focused oil and gas exploration and production company Echo Energy Plc (AIM:ECHO) has undertaken a year of rebuilding after a tough 2020.
Echo pursues a full-cycle strategy, balancing exploration and production between its two primary assets. The company has a 70pc interest in the Santa Cruz Sur licence located in southern Argentina’s onshore Austral Basin producing from Upper Jurassic and Lower Cretaceous reservoirs, with respective 1P and 2P reserves – net to Echo – of 4.3 MMboe and 13.7 MMboe. Before the pandemic Echo’s share of Santa Cruz’s production was 2,633 boepd (H1 2019).
Echo’s other key asset is its 19pc interest in the nearby Tapi Aike gas exploration permit, which has estimated gross unranked prospective resources of 4.2 Tcf mid case, 6.0 Tf Pmean, and 12.4 Tcf high case. Legacy 2D and recently acquired 3D seismic data has identified a cluster of exploration wells and more than 40 leads.
The pandemic exacerbated the company’s debt issue – at the end of 2020 Echo carried loans of $27,276,015 – forcing the shut-in of several production wells. This year the company has focused on bringing Santa Cruz back online to take advantage of rising energy prices, and the restructuring of its debt. It has also executed a strategic shift, moving away from higher-risk exploration spend to lower risk-production opportunities with shorter pay back periods.
By the publication of its half-year update Echo was able to report total net aggregate production for H1 2020 was back up to 304,639 boe, including 37,159 bbls of oil and condensate and 1,605 MMscf gas. Earlier this month the company reported that production from January to the end of November had reached a total of 523,735 boe net to Echo, including 74,605 bbls of oil and condensate and 2,695 MMscf of gas. Work to increase infrastructure capacity had facilitated gas production in November 2021 of an average of 7.1 MMscf/d net to Echo, an increase over 6.7 MMscf/d for the previous month. Work continued to bring non-producing reserves back into production. The company was also testing Campo Limite, a well in the Palermo Aike concession, with work ongoing to optimise commercial arrangements to enable activities to resume once pandemic constraints (which were in place throughout H1 2021) are lifted.
Earlier in the year Echo completed a debt restructuring process, holders of the company’s publicly listed bonds voting to allow it to defer cash interest payments on its listed bonds until mid-May 2025. Higher energy prices further relieved the company’s financial position. By May Echo was selling gas to the spot market at an average price 151pc higher than the March 2021 average. New gas sales agreements had been agreed, significantly increasing winter pricing. The company posted an H1 2021 gross profit of $0.4m for H1 2021, against a loss of $1.6m for the equivalent period for the previous year. Revenue was up 5pc to $5.9m (H1 2020: $5.6m), comprising $2.1m oil sales and $3.8m gas. Oil prices realised in H1 2021 were on average 21pc higher during the period than in H1 2020.
After spiking briefly at 1.39p in the spring following the company’s debt restructuring, its share price is back to the region it started the year, around 0.5p. Echo Energy has issues to contend with, but as the company continues to ramp up production its financial position should continue to brighten through 2022, opening possibilities for a revaluation.
Egdon Resources (AIM:EDR), an exploration and production company primarily focused on UK hydrocarbon-producing onshore basins, is moving into 2022 with several intriguing prospects.
The company’s flagship asset is its 30pc interest in the Wressle Field, which has a gross 2P Reserves of 0.62 million barrels of oil and 2C Resources of 1.53 million barrels. Wressle’s oil began flowing early this year, but recompletion and reperforation of the field’s Ashover Grit reservoir facilitated a significant breakthrough in September, when the reservoir recorded instantaneous flow rates in excess of 884 bopd and 480,000 cubic feet of gas on a significantly restricted choke setting (30.5/64ths) with a high flowing wellhead pressure. Production so far has significantly exceeded expectations, but limitations of the current gas handling equipment mean the full flow potential of the well has yet to be fully tested. The venture partners are working to remove current production constraints and to advance plans for the development of Wressle’s other hydrocarbon bearing reservoirs.
Egdon has interests in a cluster of other producing assets, including Ceres (10pc), which has produced at a rate of 58 boepd this year, and is due to run down within the next five years; Keddington (45pc), which produces at net 8 bopd from a single well; and Fiskerton Airfield (80pc), producing at a net rate of 12 bopd. A subsurface review of the Keddington field and the surrounding licence area indicates that gross Mean Contingent Resources of 559,000 barrels remain to be produced. A near-field exploration opportunity exists at Keddington South with a gross Mean Prospective Resource Volume of 635,000 barrels of oil, and the Louth Prospect has a gross Mean Prospective Resource of 600,000 barrels of oil.
But Egdon’s most interesting new prospects would seem to be its 35.8pc and 50pc interests at Biscathorpe and North Kelsey. A proposed sidetrack at the Biscathorpe-2 well is targeting the Dinantian Carbonate, a 68-metre oil column estimated to offer a gross Mean Prospective Resource volume of 2.55 million barrels of oil (mmbo), and overlaying Basal Westphalian Sandstone with the potential to add gross Mean Prospective Resources of 3.95 mmbo. Commercial screening conducted by Egdon indicates break-even full cycle economics to be $18.07 per barrel with an NPV (10) valuation of £55.60m. A planning application submitted earlier this year was rejected by the local authority last month, but the venture partners are weighing options for an appeal. North Kelsey may be an analogue to the Wressle field, with estimated Mean Prospective Resources of 6.47 million barrels in multiple reservoirs. A planning decision is awaited.
Edgon also has a significant unconventional resources portfolio of licences in Northern England, totalling 151,742 net acres with estimated Mean volumes of undiscovered gas in place of 37.6 TCF. These include the Gainsborough Trough, where the results from the 2019 Springs Road-1 well, in which Egdon has a 14.5pc interest, highlighted a potentially world class resource in the Gainsborough Shale. The moratorium on hydraulic fracturing for shale-gas imposed in November 2019 effectively end progress, but Egdon continues to appeal to the Government on the basis of its claim that UK sourced shale-gas would have significantly lower pre-combustion carbon emissions than gas imported via LNG or long-distance pipelines. Other notable interests include an MoU with Creative Geothermal Solutions Limited in respect of potential geothermal projects at Egdon’s Dukes Wood-1 and Kirklington-3Z wells.
The company’s most recent preliminary results published last month recorded modest production for the year to 31 July of 90 boepd, although Wressle has facilitated production guidance for 2021-22 of 240 boepd. Revenue from oil and gas production during the year was £1.09m (2020: £0.96 million), helped by an increase in commodity prices that secured an 84pc increase in realised price per boe. Egdon recorded a net loss of £1.68m for the period, though this was less than the loss of £4.75m recorded in 2020. Cash at bank as at 31 July 2021 was £1.96m. The company refinanced the business earlier in the year through a £1m loan facility, the issue of £1.05m convertible loan notes, and an equity placing of £1.44m.
Egdon currently has a modest set of producing assets, and a corresponding share price of 1.22p (at the time of writing) and market cap of £6.33m. But it has interesting prospects at Wressle and Biscathrope, the former continuing to produce strongly according to the company’s most recent operations update. If Wressle continues to make good on its initial promise, and the company gets a regulatory break at Biscathrope, and the green light for its North Kelsey prospect, Egdon Resources may be set for an interesting 2022.
IGas Energy (AIM:IGas), the UK’s largest independent onshore oil and gas operator with interests in more than 50 licences across England and Scotland, has taken further steps to position itself as a transitional company this year, with a growing set of geothermal, hydrogen and solar projects.
IGas continues to produce oil and gas, citing the UK Committee on Climate Change forecast that the UK’s demand for gas will still be 70pc of its current level in the year 2050. But the company’s most recent set of interim results elaborated its ambition to transform many of its sites into ‘integrated hybrid energy hubs, encompassing combinations of solar, modular hydrogen, Carbon Capture, Utilisation and Storage and battery storage.’
This shift of focus is charged with some urgency given the natural decline in the company’s oil and gas assets acknowledged in its communications. But IGas insists their course of life has some years to run yet. The company’s interims stated an average net production for the six months to 30 June 2021 of 2,005 boepd. A revised CPR published earlier this year estimated Reserves and Resources as at 31 December 2020 of 1P 11.74 MMboe, 2P 17.12 MMboe and 2C 20.35 MMboe, with a replacement rate for 2P reserves of approximately 250pc. Some 85pc of the 2P is already developed, requiring no further significant capital investment. The report valued the company’s assets at around $204m on a 2P NPV10 basis, and $150m on a 1P NPV10 basis. More than half of the company’s production is focused on the Weald Basin in southern England, which has produced more than 21 million barrels of oil to date.
IGas had hoped to significantly extend its resource by exploring its fields’ capacity for shale gas, an aspiration that seems to have been closed by the moratorium on fracking imposed just over two years ago. The company hasn’t given up hope, applying – so far unsuccessfully – to extend the operational period for its Springs Road site in Nottinghamshire, which targets the ‘world-class’ Gainsborough Trough, for a further three years.
But IGas’s prospects for developing its evolving geothermal and hydrogen programmes seem much rosier. The company brought in geothermal expertise last year with the acquisition of specialists GT Energy, and is progressing a pathfinder geothermal project to provide district heating in Stoke which it believes will demonstrate the commercial potential for geothermal energy production from repurposing existing oil and gas assets for ‘direct heat for agriculture, residential heating and cooling, and the development of hybrid energy systems generating both heat and power’.
IGas has also taken practical steps to explore the capacity of its assets to generate hydrogen, identifying two ‘blue hydrogen’ candidate sites in Surrey. The Albury site would generate 1000kg/day of hydrogen, and Bletchingley 2000kg/day, offering a potential of up to 6000kg/day depending on reserves. Discussions with potential offtakers are taking place for both projects. ‘Blue hydrogen’ relies gas to produce hydrogen, integrated with carbon capture and storage to gather emissions.
In October IGas signalled its interest in solar through an agreement with renewable energy investor Iona to jointly develop utility scale solar farms in the UK, beginning with a 25-40MW project in southern England. And earlier this month the company joined the industry consortium Net Zero RISE exploring the repurposing of existing onshore oil and gas infrastructure as research sites for carbon sequestration, hydrogen storage and closed-loop geothermal technologies.
Refreshingly, then, IGas isn’t just talking about geothermal, hydrogen and solar but taking practical steps to develop working projects. For now it continues to depend on its hydrocarbons revenues. In the six months to 30 June the company generated revenues of £16.6m from sales of 330,984 barrels of oil, 7,112 Mwh of electricity and 1,247,946 therms of gas, up from £10.5m for the previous year, during which of course demand was hit by the outbreak of the pandemic. Production is now recovering, up – as reported above – to 2,005 boepd, from 1,940 boepd for the equivalent period a year ago. The company stated a cash balance of £2.8m (H1 2020: £2.6m), an operating cash flow of £6.4m (H1 2020: £1.4m), and an adjusted EBITDA of £2.7m (H1 2020: £2.2m). It does however carry a net debt of £13.2m (H1 2020: £11.2m), but secured a Reserve Based Lending facility (RBL) redetermination in June, confirming £19.5m of debt capacity and headroom of £6.4m.
IGas’s share price has oscillated significantly this year within the 15p to 30p range. But aside from a sudden spike in September at the outset of the UK’s gas supply crisis, the price has been around 15p since the spring. At the time of writing it is right down to 12.85p. The company is sitting on a substantial share resource, but seems unlikely to have the opportunity to develop it. IGas, then, might be viewed as a longer term holding for investors keen to support the UK’s energy transition.
Jersey Oil & Gas
Jersey Oil & Gas (AIM:JOG) is an upstream oil and gas company focused on the UK Continental Shelf region of the North Sea, with a fully owned set of blocks – referred to as the Greater Buchan Area (GBA) – encompassing the Buchan oil field, J2 oil discovery, the P2170 Licence Blocks 20/5b & 21/1d, and the Verbier oil discovery. The GBA is estimated to contain 172 MMboe of discovered P50 recoverable resources net to JOG, and significant exploration upside potential of approximately 168 MMboe of prospective resources.
Jersey has submitted a Concept Select Report (CSR) for the GBA Development to the Oil and Gas Authority (OGA), detailing a three phase plan, beginning with the development of the Buchan oil reservoir, that the company believes will generate an early income stream that could be offset against future phased development expenditure.
The Report also details an interesting electrification concept designed to green the project, and cut costs. Jersey proposes powering operations through electricity supplied by a cable from shore to the planned production platform, significantly reduce carbon emissions associated with production. The company estimates platform electrification could reduce emissions to less than 1kg/boe, compared to an industry average in the UK North Sea of approximately 22kg boe. Jersey has undertaken a subsea survey to cover a potential cable route from shore to the proposed Buchan platform location. Indeed the GBA Development has the potential to be an integral part of an area-wide electrification project through collaboration with other industry parties and stakeholders, a shared approach which could reduce capital and operational costs further.
The project economics envisage pre-tax free cashflow of $6.4bn with an NPV (pre-tax) of $1.7bn. Operating costs during plateau production – estimated to persist for more than three years – are estimated at $8/boe to $9/boe, with a payback period estimated at under three years. Total project costs based on current day values are estimated to be approximately $30/boe. Jersey has launched a sales process to farm-out an interest in the GBA Development licences to secure an industry partner and funding towards costs.
Jersey undertook a £16.6m placing in March to support its current programme. The company’s cash position was approximately £17.1m as of 30 June 2021. It hopes to raise further funds through the decision to relinquish its non-core P2497 (Zermatt) and P2499 (Glenn) licences.
Jersey Oil & Gas has much work to do to move the GBA Development into production, but with OGA approval for its application to act as Installation Operator for the Design Phase of the planned Buchan platform, negotiations with pipeline operators underway, and a practical plan for achieving net zero, its plans to become a North Sea producer are worth following in 2021. The company’s share price is currently around 135p, slightly up on the year, but well down from its February peak of 250p.
Longboat Energy (AIM:LBE) is an emerging North Sea exploration and production company with interests in seven near-term exploration wells in the Norwegian Continental Shelf (NCS).
Established by the ex-Faroe Petroleum plc management team, which was sold to DNO ASA in January 2019, Longboat’s stake in the wells, which target net mean prospective resource potential of 104 MMboe with an additional 220 MMboe of upside, was acquired through farm-in transactions with Equinor Energy AS, Spirit Energy Norway AS, and Idemitsu Petroleum Norge AS. Longboat believes the resource has potential to create a Net Asset Value of more than $1bn based on precedent transactions in the Norwegian North Sea sector. The farm-ins were supported by a £35m equity raise and a £50m Exploration Finance Facility with SpareBank 1 SR-Bank ASA and ING Bank NV. The cost of the carry element of the farm-ins is eligible for the Norwegian tax refund system, reducing the net cost to the company to $7.8m on a post-tax basis.
The venture partners are currently exploring four wells. Rodhette, in which Longboat has a 20pc interest, is estimated to have a 41pc chance of success, and to contain gross mean prospective resources of 41 MMboe with further potential upside bringing the total to 81 MMboe. Egyptian Vulture (15pc interest) has an estimated 25pc chance of success and gross mean prospective resources of 103 MMboe with further potential upside bringing the total to 208 MMboe. Mugnetind (20pc interest) is estimated to contain gross mean prospective resources of 24 MMboe with further potential upside bringing the total to 47 MMboe, and a 51pc chance of success. Ginny/Hermine (9pc interest) is estimated to contain gross mean prospective resources of 41 MMboe for Ginny and 27 MMboe for Hermine, with further potential upside bringing the respective totals to 84 MMboe and 45 MMboe: it has a 22pc chance of success.
Longboat reported early progress in October. A 29-metre hydrocarbon column in the primary target in the Middle Jurassic Stø Formatio has been encountered at Rødhette, data acquisition indicating a gas column of approximately 18 metres in the well overlaying an oil rim. Two weeks later light oil in the primary target in the Lower Cretaceous (Cenomanian) Intra-Lange Formation was encountered at Egyptian Vulture. The top of the reservoir was reached close to prognosis at a vertical depth of 3,684 metres below sea level with 13 metres net sand in a 37 metre oil filled gross interval. Drill results from the first three wells – Mugnetind has spudded – are expected ‘before the end of the year’.
Longboat Energy is a speculative venture, but is currently flush with cash sufficient for exploration of a set of promising wells in Norway’s well proven waters. The company’s management have a track record, having grown Faroe Petroleum’s reserves from 19 MMboe to 98 MMboe between 2013 and 2018. Longboat’s shares have drifted between the 70p to 90p region this year, and are currently close to the lower end of that range. It’s well worth keeping an eye on the company’s progress in the new year as it reports on progress with its first four targets.
Nostra Terra Oil and Gas
Nostra Terra Oil and Gas (AIM:NTOG), an exploration and production company with a portfolio of assets in three different Texas basins, has weathered the crisis that hit many of its peers in the region when the pandemic took hold last year, and taken advantage of this year’s surge in oil and gas prices.
Focused on shallow, conventional reserves in Texas, the company is built on a foundation of low risk, producing assets with development upside. The company’s primary asset is a 100pc working interest in Pine Mills, a 2,400 acre producing oil field in eastern Texas which has produced over 12 million barrels of oil since its discovery in 1950s. Since taking ownership Nostra Terra has focused on low-cost workovers and upgrades to increase production and overall uptime.
Last year the company farmed-out an undrilled 80-acre portion of the field to Cypress Minerals LLC in return for a 25pc carried working interest on the first well drilled. The farm-out secured a near doubling of gross production at Pine Mills, taking it to more than 100 bopd, and a second well is currently being planned. The company has a 50 to 75pc interest in a set of leases in western Texas, and last year took a 100pc interest in the producing Caballos Creek Oil Field to the south of the state. All produce from conventional reservoirs with long-life reserves.
Though Nostra Terra’s relatively conservative asset base did not leave it as exposed to last year’s downturn as many of its indebted neighbouring operators, particularly shale producers, the pandemic presented challenges, which the company addressed by cutting operating and overhead costs by nearly two-thirds and hedging more than half its production. The company’s final results for the year ended 31 December 2020, published in June, reported revenues for the year of $1,010,929, down from $1,795,000 in 2019, reflecting the slump in oil prices and a decline in production from temporarily shutting in assets at the peak of the pandemic. Interim results published in September for the six-month period ended 30 June 2021 reflected the significant upturn in oil prices, helping the company record an average sales price for the period of $63.28 per barrel, compared to $25.45 for the first half 2020. Together with a 25pc increase in total production to 15,211 barrels oil, up from 12,152 barrels, the price rise secured a 130pc increase in revenue to $963,000, up from $417,000. Gross profit from operations swung from a loss of $115,000 to a $250,000 profit, and the loss for the period fell from $437,000 to $269,000. The company expects to be cashflow positive for the full year 2021.
An independent reserves upgrade, supercharged by rising prices, estimated that an increase of 27pc to 1,994,240 gross barrels oil had the potential to yield just under $24m future net income (total proved), a 58pc increase from 2019 year end. The reserve estimates rose further a few weeks later to reflect the continued rise in prices, $68.5m future net income (total proved) forecast on the assumption of a $75 oil price. The company’s November operations update confirmed that the farm-out well at Pine Mills was continuing to produce at strong levels, with no decline. The company reported a 44pc increase in production for the first half of the year to 121 net bopd, up from 84 net bopd in H1 2021. Improved cashflow is allowing the company to plan new development wells in the field, which it anticipates operating with at least 90pc working interest.
Conditions, then, would seem to favour operators like Nostra Terra that have positioned themselves to generate decent profits through inexpensive production. Aware, however, of the need to inject life into a share price that has drifted down to less than 0.4p from highs of more than 5p three years ago, the company ‘has negotiated terms and is waiting final approval’ regarding a new opportunity in Tunisia, ‘a large block with existing discoveries, offering both exploration and appraisal activity.’
Nostra Terra’s shareholders have waited for some time for the company’s stars to align, but having come through 2020 better than many of its peers, and moving into cashflow positive territory with new assets on the horizon, this is a small cap entering the new year with confidence.
Despite an eventful year in which the company has had to navigate several challenges, surging natural gas prices have helped Prospex Energy Plc (AIM:PXEN) progress a set of revenue generating natural gas plants in Spain and Italy.
This March Prospex took a 49.9pc stake in the El Romeral integrated natural gas production and power station project in southern Spain. Operated by Tarba Energia, the project encompasses three producing wells with gross 2P reserves of 0.30 Bcf, multiple additional prospects, an 8.1 MW power station, and a contract in place to supply General Electric. All three wells are late life, restricting operations to a fifth of the plant’s capacity. But the project has 11 further prospects offering a cumulative 90 Bcf of gross un-risked prospective resources, and two development locations with gross contingent resources of 5 Bcf. Prospex estimates that bringing just one new well online would be sufficient to allow the plant to produce at its maximum capacity of around 60,000 MWh gross per annum, which at Spain’s historic average electricity price of €70 per MWh would deliver indicative project level pre-tax annual revenues and profit before tax of €4.2m and €2.4m respectively. Prospex has another Spanish interest, a 15pc stake – with a 49.9pc option – in Tesorillo, a large gas project in the south of the country with estimated gross unrisked prospective resources of 830 Bcf, and two existing petroleum exploration licences.
The company also has a significant interest in Italy through its 17pc stake in the Podere Gallina project in the Po Valley Basin, which has 13.4 Bcf P50 reserves, gross contingent resources of 14.1 Bcf (2C), and gross prospective resources of 88.2 Bcf (best estimate). The venture partners’ current focus is bringing the project’s Selva Malvezzi natural gas field online, which, integrated with a fully automated gas plant, has the potential to produce at an initial daily rate of up to 150,000 cubic metres. Prospex is in discussion with potential non-equity funders to meet its €580,000 share of the cost of bringing Selva into production. The project passed a significant landmark in April when full environmental approval was secured from regulators for connection to Italy’s national gas grid, paving the way for the grant of a full production licence from the country’s Economic Development Ministry. Prospex has signed a conditional sale and purchase agreement to increase its holding in Podere Gallina to 37pc. The deal, which the company expects to deliver ‘via a balance of both equity and debt finance’, would increase the company’s share in Selva’s 2P gas reserves to 5 Bcf, and add 2.7 Bcf of 2P gas reserves to its portfolio.
Prospex has had to weather a few storms this year. In May the Spanish government passed a Climate Change and Energy Transition Act ruling against the granting of new hydrocarbon permits or licences in the country. The law complicates the efforts of Prospex’s joint venture partner, Tarba Energía, to upgrade an exploration permit for the Tesorillo gas project into an exploitation concession. But the partners have received legal advice confirming that applications made on the basis of permits that existed prior to the Act coming into force – like that for Tesorillo – retain their validity under the new law. There was another setback in October when a workover at the first candidate well at El Romeral the company is trying to bring back to production was unsuccessful. There was somewhat better news earlier this month, when the company reported that its plant optimisation project at El Romeral had been completed successfully, opening the way for ‘an increase in power generation income of up to 65pc’. In October Prospex reported that the tie-in of the Selva field to Italy’s national gas grid would be delayed, pushing back the likelihood of first gas from mid-2022 to 1H 2023. Regulators did however confirm that Selva’s production concession is likely to be granted in Q1 2022.
The company has reported strong financial progress this year as gas prices have surged.Its most recent set of interims reported a net profit from operations of £129,356 against a loss of £1,027,875 for the previous period. The company recorded a 13.48pc increase in the net book value of its investments to £4,109,225, up from £3,620,890 in 2020, a revaluation of the company’s share in the Podere Gallina licence allowing it to note unrealised gains on its financial assets of £488,335, against a loss for H1 2020 of £664,949.
Though Prospex has faced its fair share of challenges this year the company’s share price has risen from less than 1.5p in May to around 3.3p (at the time of writing), touching highs of 4.25p in September. Its stock is up more than 70pc in the past year, taking the company’s market cap to £5.7m. Prospex’s path continues to be shadowed by uncertainties, but this is a company with producing assets serving a dynamic market, and with good prospects for bringing additional production capacity online over the next 18 months.
Union Jack Oil
Union Jack Oil (AIM:UJO) is a UK focused onshore exploration and development company with stakes in a set of producing and exploratory assets around the Humber, Britain’s biggest energy hub.
The company has several interests in common with UK peer Egdon Resources, discussed above. It has a 40pc interest in the PEDL180 and PEDL182 fields at Wressle, which have a gross 2P Reserves of 0.62 million barrels of oil and 2C Resources of 1.53 million barrels. As noted in our commentary on Egdon, there was a significant breakthrough at the field’s Ashover Grit reservoir in September, when instantaneous flow rates in excess of 884 bopd and 480,000 cubic feet of gas were recorded, on a restricted choke setting with a high flowing wellhead pressure. The venture partners are working to upgrade the site’s infrastructure to allow the well’s full potential to be tested, and to advance plans for the development of Wressle’s other hydrocarbon bearing reservoirs.
Like Egdon, Union Jack also has stakes in the Biscathorpe, North Kelsey and Keddington fields. The company has a 45pc stake in the PEDL253 field at Biscathorpe, where a proposed sidetrack at the Biscathorpe-2 well is targeting a 68-metre oil column estimated to offer a gross Mean Prospective Resource volume of 2.55 MMbo. The venture partners are weighing options for appealing a planning application rejected by the local authority last month.
Union Jack has a 50pc interest at North Kelsey, which may be an analogue to the Wressle field, with estimated Mean Prospective Resources of 6.47 million barrels in multiple reservoirs, and a 55pc stake in the PEDL005(R) field at Keddington, which has gross remaining Mean Contingent Resource is estimated at 567,000 barrels of oil (311,000 net to Union Jack). There is a near field exploration opportunity at Keddington South, which has a gross Mean Prospective Resource of 759,380 barrels of oil (417,659 barrels net).
Union Jack also has a 16.665pc interest in the WNA-1, WNA-2 and WNB-1z discoveries at the PEDL183 field in West Newton. The wells are on-trend with the established offshore Hewett gas complex, targeting Permian Basin carbonates analogous to those extensively explored and produced onshore in the Netherlands, Germany and Poland. An Extended Well Test (EWT) is currently underway, probing a 65 metre hydrocarbon column in the prospect’s Kirkham Abbey formation which is suspected to have been subject to well bore damage, making it sensitive to fluid and water, and constraining its capacity to flow. Gas and light oil/condensate have been recovered to surface from both the WNA-2 and WNB-1z wells, and multiple samples have been gathered for analysis.
Union Jack expanded its portfolio into the North Sea this year by taking a 2.5pc interest in the Claymore Piper Royalty Complex. The Complex has so far produced more than 1.8 billion barrels of oil and 262 Bcf of gas. The company views the acquisition as an attractive low-risk entry strategy to the North Sea offering a reliable return without exposure to operational risk. The asset is expected to deliver a sustained cash flow for at least 10 years.
The company is financed to progress its current opportunities, having raised £3m in the autumn for investment in Wressle’s infrastructure and the funding of the planned side-track well at Biscathorpe. As of 16 December 2021, it had a cash balance of £6,068,000 and projected revenues to 31 December 2021 of around £1,760,000 (2020: £241,467).
Over the past few months Union Jack’s share price has fallen to its lowest level since the outset of the pandemic last year. After oscillating between 30p and 40p for most of the year the price dipped to just under 14p. But opportunities at Biscathorpe and West Newton remain, operational and regulatory challenges notwithstanding, and Wressle continues to comfortably exceed initial expectations of 500 barrels of oil per day (gross), earning the company $1m since the successful intervention. Investors seeking opportunities to take a stake in Britain’s native gas infrastructure may want to follow Union Jack’s story.
Westmount Energy (AIM:WTE) offers AIM investors access to exploration in the highly prospective Guyana-Suriname Basin through material indirect holdings in a cluster of key licences.
More than 50 wells have been drilled in the Basin since 2015, yielding 11 billion oil equivalent barrels, with perhaps twice as many waiting to be discovered. Through its investee companies Westmount has had interests in six wells – Jethro-1, Joe-1, Tanager-1, Bulletwood-1, Jabillo-1 and Sapote-11 – three of which have yielded discoveries. To date none have produced commercial success, but the company continues to hold stakes in ongoing exploration.
Westmount has a holding of 5.3pc in Cataleya Energy Corporation, which in turn has a 20pc interest in the first well on the Kaieteur Block, Tanager-1, the deepest well drilled in the Guyana-Suriname Basin to date. The well is targeting a Best Estimate Unrisked Gross (2C) Contingent Oil Resource of 65.3 MMBBLs. Although high quality reservoirs have been encountered, initial interpretation of the reservoir fluids has been inconclusive: the discovery is currently considered to be non-commercial as a standalone development. The company has an interest in the Basin’s Canje Block through a 7.2pc holding in JHI Associates Inc, which has a 17.5pc stake in the Block’s maiden Bulletwood-1 well, completed in March. Again, quality reservoirs have been encountered, but as yet no commercial hydrocarbons. JHI is fully funded for the drilling of additional wells. It’s a similar story at the Orinduik Block, where Westmount has a 0.75pc interest in Eco (Atlantic) Oil and Gas Ltd, which in turn has a 15pc stake in ongoing drilling. The Block’s venture partners have been analysing 2019/20 drilling results indicating a Cretaceous light oil prospect inventory that will be the focus of future exploration. Westmount has a minor indirect interest in Block 47, Suriname, through a 0.04pc holding in Ratio Petroleum, which has a 20pc stake in operations overseen by Tullow Oil. This year’s drilling was abandoned after encountering a good quality reservoir that yielded only minor oil shows.
Westmount acknowledges that ‘initial drilling outcomes are below our expectations for the portfolio’, but believes results so far must be viewed as first steps in the process of evaluating giant stratigraphic prospects. The company ‘remains hopeful that the geoscience learning curve combined with the portfolio effect provided by drilling an extended sequence of prospects in this prolific basin will win out over individual prospect risks to yield a commercial discovery.’ Drilling to date has confirmed the presence of high-quality reservoirs of various stratigraphic ages in the Kaieteur, Canje and Orinduik areas, which are capable of supporting deep-water developments when containing commercial volumes of light oil. Further drilling is planned across Westmount’s interests, and the Basin continues to be a focus of majors including ExxonMobil, Chevron and Qatar Petroleum.
The company continues to look out for investment opportunities, noting that there are likely to be some consolidation opportunities within the basin amongst the junior players, as exploration matures and investors adjust their risk management strategy. Westmount Energy’s share price has tumbled this year from around 20p to less than 6p in response to disappointing results, but is still the only AIM listed junior player offering exposure to offshore Guyana.
US focused Zephyr Energy (AIM:ZPHR) was one of this year’s highest flying small cap stocks after making significant progress to transform itself from a single project exploration company to a cash-generating oil and gas producer. The company achieved breakthrough discoveries at its operated asset, the Paradox Project in Utah, and built a portfolio of non-operated assets in established oil producing basins.
Zephyr has a 75pc working interest in Paradox, which covers some 200 potential well locations across 37,613 gross leased acres. Current estimates indicate a range of risked net recoverable contingent resources of up to 143 MMboe, with the Cane Creek reservoir, the prime target, offering up to 30 potential well locations with a range of risked net recoverable contingent resources of up to 18 MMboe.
The company completed drilling operations at well State 16-2LN-CC in August, and earlier this month announced a successful test highlighting the well’s potential to drain a larger hydrocarbon resource with stronger economics than initially forecast. The well averaged daily rates of 716 boepd with highs of 1,083 boepd achieved with limited pressure drawdown, with initial simulation modelling suggesting possible plateau rates of 2,100 boepd. Gas rates were substantially higher than expected, with modelling suggesting the well is capable of production plateau rates of 10 million square cubic feet of gas per day and 500 boepd of liquids. Zephyr stated a single well potential Estimated Ultimate Recovery of 2.65 MMboe, significantly higher than pre-drill estimates of up to 0.85 MMboe, and has commissioned a new CPR, expected early next year. The company is proceeding with plans to equip the well and facilitate the sale of hydrocarbons.
Earlier in the year Zephyr completed four acquisitions at Williston Basin, North Dakota, for some $4m, giving the company working interests in 22 wells across multiple pads and operators. Seven wells are currently producing, with 15 drilled and awaiting completion. Q2 2021 production averaged 148 boe per day net to Zephyr, with an average realised sales price of $52.90 per boe. The company estimates up to $8m of undiscounted cash flow over the next 12 months, and a total of $15m of undiscounted cash flow over the lifetime of the project. Revenues will fund future Paradox development and additional projects.
Zephyr acquired another Williston asset, the Continental acreage operated by Continental Resources, the Basin’s largest operator. The acreage has, net to Zephyr, estimated 2P reserves (from all 24 wells) of circa 60,000 boe, with 1P reserves estimated at 41,000 boe and the 3P reserves at 72,000 boe. During Q2 2021 Zephyr’s net production from the Williston Basin wells averaged 148 boe/d with an average realised sales price of $52.90 per boe. In November the company entered into an agreement to acquire working interests in 163 more producing wells in the Basin, with approximately 871 boepd net to the assets being produced in September 2021.
Zephyr has emphasised its commitment to ESG this year, delivering on a pledge to meet 100pc carbon-neutral Scope 1 targets across its full operational footprint. The company has collaborated with the Prax Group, a British multinational independent oil refining, trading, storage, distribution and retail conglomerate, to measure, reduce and mitigate emissions across Zephyr’s businesses. Mitigation is primarily focused on the purchase of sustainability/decarbonisation offsets from pre-vetted developers of sustainable projects.
Zephyr completed a £10m fundraise in April to fund drilling operations on the Paradox project and the acquisition of non-operated assets. Revenues from its newly acquired Whiting wells at Williston for the six months ended 30 June 2021 were $0.9m. The company expects revenues for the second half of the financial year will be considerably higher as it will not only include revenues for a full six-month period but will also include revenue from all five of the Whiting wells, some of which came online until after 30 June. Net loss after tax from continuing operations for the period was $1m. Cash at 1 September 2021 was $4m.
Zephyr Energy has had a positive year in the field, and a stellar one in the markets: its share price has surged 730pc, up from less than a penny in January to 6.8p at the time of writing, taking its market cap to £89.5m. The company is now under pressure to keep the good news flowing, particularly at Paradox. If it can, then, supported by a strong outlook for oil and gas prices, its stock might have further to climb.